The present invention relates to refining and converting heavy hydrocarbon fractions also comprising sulphur-containing impurities. More particularly, it relates to a process for converting at least a portion of a hydrocarbon feed, for example a vacuum residue obtained from straight run distillation of a crude oil into good quality light gasoline and gas oil fractions and to a heavier product which can be used as a feed for catalytic cracking in a fluidised bed catalytic cracking unit comprising a double regeneration system and optionally a system for cooling the catalyst in the regeneration step. The present invention also relates to a process for producing gasoline and/or gas oil comprising at least one fluidised bed catalytic cracking step.
One aim of the present invention is to produce readily upgradeable lighter fractions such as middle distillates (engine fuel: gasoline and gas oil) and base stock from certain particular hydrocarbon fractions which will be described in more detail below, by partial conversion of those fractions.
Within the context of the present invention, the conversion of the feed to lighter fractions is normally in the range 10% to 75% or even 100% if the unconverted heavy fraction is recycled, usually in the range 25% to 60%, or limited to about 50%.
Feeds which can be treated by the process of the present invention are atmospheric residues or straight run vacuum residues, deasphalted residues, residues from a conversion process such as those from coking, fixed bed hydroconversion such as those from HYVAHL(copyright) processes for treating heavy hydrocarbons developed by the Applicant, or heavy hydrocarbon hydrotreatment processes carried out in an ebullated bed such as those from H-OIL(copyright) processes, or solvent deasphalted oils, for example using propane, butane or pentane, or asphalts normally originating from deasphalting straight run vacuum residues or vacuum residues from H-OIL(copyright) or HYVAHL(copyright) processes diluted by hydrocarbon fraction or a mixture of hydrocarbon fractions selected from the group formed by a light cycle oil (LCO), a heavy cycle oil (HCO), a decanted oil (DO), a slurry and gas oil fractions in particular those obtained by vacuum distillation known as vacuum gas oil (VGO). The feeds can also be formed by mixing those various fractions in any proportions, in particular atmospheric residues and vacuum residues. They can also contain gas oil cuts and heavy gas oil cuts originating from catalytic cracking, generally with a distillation range of about 150xc2x0 C. to about 370xc2x0 C. or 600xc2x0 C. or more than 600xc2x0 C. They can also contain aromatic extracts obtained from manufacturing lubricating oils. In accordance with the present invention, the feeds which can be treated are preferably atmospheric residues or vacuum residues, or mixtures of such residues.
The aim of the present invention is to produce good quality products particularly with a low sulphur content under relatively low pressure conditions, so as to limit the cost of plant. This process can produce a gasoline type engine fuel containing less than 100 ppm by weight of sulphur thus satisfying the most strict regulations governing sulphur content for this type of fuel, from a feed which may contain more than 3% by weight of sulphur. Similarly, and this is of particular importance, a diesel type engine fuel is obtained with a sulphur content of less than 500 ppm and a residue with an initial boiling point of about 370xc2x0 C., for example, which can be sent as a feed or part of a feed to a residue catalytic cracking step such as a double regeneration step.
The prior art includes descriptions, in particular in United States patents U.S. Pat. Nos. 4,344,840 and 4,457,829, of processes for treating heavy hydrocarbon feeds comprising a first treatment step carried out-in the presence of hydrogen in a reactor containing an ebullated catalyst bed followed by a second fixed bed hydrotreatment step. Those descriptions illustrate the case of fixed bed treatment, in the second step, of a light gas fraction from the product from the first step. It has now been discovered, and this forms one of the aspects of the present invention, that it is possible to use a second step to treat either the whole of the product from the first ebullated bed conversion step or a liquid fraction from this step by recovering the gas fraction converted in the first step under favourable conditions leading to good stability of the system as a whole and to improved middle distillate selectivity. There are other processes for treating heavy hydrocarbon fractions. Thus the Applicant""s French, United States and European patents FR-A-2 480 7773, U.S. Pat. No. 4,391,700, FR-A-2 480 774, EP-A-0 113,283, EP-A-0 113 284 and EP-A-0 297 950 describe processes for converting heavy feeds comprising a thermal conversion step, usually termed the hydrovisbreaking step and one or more catalytic steps. Those processes have the disadvantage of forming, in the thermal conversion step, a large quantity of olefinic compounds which then risk clogging the catalyst used in a subsequent step and accelerate its deactivation. A process is also known wherein moving bed treatment is followed by a step for treating the effluent leaving the moving bed in a fixed bed reactor. This type of process is, for example, described by SHELL in the article entitled xe2x80x9cThe SHELL residue hydroconversion process: development and achievementsxe2x80x9d presented at the ACS 213th National Meeting, San Francisco, Apr. 13-17, 1997, or by the OCR process from CHEVRON using a counter-current moving bed described in the article entitled xe2x80x9cOn line catalyst replacement, OCRxe2x80x9d published in the Oil and Gas Journal, Oct. 12, 1992, pages 52 to 54. Processes from the Institut Francais du Pxc3xa9trole which were, for example, presented at the NPRA annual meeting, Mar. 17-19, 1991 can also be cited, which use either moving beds or guard reactors in parallel (swing reactors). All of those processes have the drawback of residue conversions which are limited because of the moving bed technology itself whereby the average reaction temperatures reached are not as high as in processes using an ebullated bed.
In its broadest sense, the present invention is defined as a process for converting a hydrocarbon feed containing at least a hydrocarbon fraction with a sulphur content of at least 0.1% by weight, normally at least 2% and usually at least 4% by weight, and an initial boiling point of at least 340xc2x0 C., normally at least 500xc2x0 C., and an end point of at least 440xc2x0 C., usually at least 600xc2x0 C., and which can be more than 700xc2x0 C., characterized in that it comprises the following steps:
a) treating said hydrocarbon feed in a section for treatment carried out in the presence of hydrogen, said section comprising at least one three-phase reactor, containing at least one hydroconversion catalyst, wherein the mineral support is at least partially amorphous, in an ebullated bed, operating in liquid and gas upflow mode, said reactor comprising at least one means (17) for withdrawing catalyst from said reactor located close to the reactor bottom and at least one means (16) for supplying fresh catalyst to said reactor located close to the top of said reactor;
b) sending at least a portion, usually the whole, of the effluent from step a) to a section for eliminating catalyst particles contained in said effluent, said section comprising at least one means for eliminating said solid particles and at least one means for recovering an effluent containing fewer solid particles than the effluent from step a);
c) sending at least a portion, usually the whole, of the effluent from step b) to a treatment section, said treatment being carried out in the presence of hydrogen and optionally a fraction of hydrocarbons added to the effluent from step b), said section comprising at least one reactor containing at least one fixed bed hydrotreatment catalyst wherein the mineral support is at least partially amorphous, under conditions enabling an effluent to be obtained with a reduced sulphur content and a high middle distillate content.
Usually, addition of a hydrocarbon fraction to the effluent from step b) enables the temperature of the fluid entering the treatment section for step c) to be readily adjusted. This hydrocarbon fraction can, for example, be selected from the group formed by VGO, LCO and mixtures of VGO and LCO, in particular a VGO fraction and/or an LCO fraction of the hydrocarbon feed which is treated within the context of the present invention.
Normally the treatment section of step a) comprises one to three reactors in series; the section for eliminating catalyst particles of step b) comprises at least one and usually at least two means for eliminating said solid particles which usually function in an alternating manner or in series; and the treatment section of step c) comprises one to three reactors in series.
In a normal implementation of the invention, at least part, normally all, of the effluent obtained in step c) is sent to a distillation zone (step d)) from which a gas fraction, a gasoline type engine fuel fraction, a gas oil type engine fuel fraction and a liquid fraction which is heavier than the gas oil type fraction are normally recovered.
In a variation, the liquid fraction which is heavier than the hydroconverted feed from step d) is sent to a catalytic cracking section(step e)) in which it is treated under conditions which produce a gas fraction, a gasoline fraction, a gas oil fraction and a fraction which is heavier than the gas oil fraction, usually termed a slurry fraction.
In a further variation, at least a portion of the liquid fraction which is heavier than the hydroconverted feed from step d) is returned either to ebullated bed hydroconversion step a) or to the fixed bed hydrotreatment step c), or in part to each of these steps. It is also possible to recycle the whole of this fraction. At least a portion of the liquid fraction which is heavier than the hydrotreated feed obtained in step d) can also be sent to the heavy fuel storage zone, known in the art as the heavy fuel pool.
The gas fraction obtained in steps d) or f) normally principally contain saturated and unsaturated hydrocarbons containing 1 to 4 carbon atoms in their molecule (such as methane, ethane, propane, butanes, ethylene, propylene, butylenes). At least part, preferably all, of the gasoline type fraction obtained in step d) is, for example, sent to the fuel storage zone known in the art as the fuel pool. At least part, preferably all, of the gas oil type fraction obtained in step d) is, for example, sent to the fuel storage zone. At least part, preferably all, of the slurry fraction obtained in step e) is usually sent to the heavy fuel pool in the refinery, generally after separating fine particles which are suspended in it. In a further implementation of the invention, at least part, preferably all, of this slurry fraction is returned to inlet to catalytic cracking step e). In a further embodiment of the invention, at least a portion of this slurry fraction can be returned, generally after separating fine particles suspended in it, either to step a), or to step c), or partially to each of these steps.
One particular embodiment of the present invention comprises an intermediate step al) between step a) and step b) in which the product from step a) is split into a heavy liquid fraction containing the majority of the catalyst particles initially present in the product from step a) and into a lighter fraction containing few or no catalyst particles which is recovered. In this implementation of the present invention, the heavy liquid fraction obtained in this step a1) is then sent to step b) for eliminating solid catalyst particles. This implementation enables light cuts obtained from hydroconversion step a) to be upgraded more easily and limits the quantity of product to be treated in step b). This lighter fraction obtained in step a1) can be sent to a distillation zone from which a gas fraction, a gasoline type engine fuel fraction, a gas oil type engine fuel fraction and a liquid fraction which is heavier than the gas oil type fraction can be recovered, at least part of which can, for example, be returned to step a) and/or be returned to converting hydrotreatment step c). The distillation zone in which this lighter fraction is split can be distinct from the distillation zone of step d), but usually this lighter fraction is sent to the distillation zone for said step d).
By way of example, solid catalyst particles can be separated in step b), these solid particles usually being the fines produced by mechanical degradation of the catalyst used in hydroconversion step a), using at least one rotary filter or at least one basket filter or a centrifuging system such as a hydrocyclone associated with filters, or in-line decanting. The scope of the invention alsoencompasses carrying out direct separation of the solid catalyst particles contained in the product from step a1) by sending the product which is concentrated in fines to step b), involving the treatment of a smaller quantity of product if separation is carried out on a liquid fraction from step a1) when this step exists. In a particular implementation of this step b), at least two separation means are used in parallel one of which is used to carry out separation while the other is being purged of retained fines.
The conditions for step a) for treating the feed in the presence of hydrogen are usually conventional ebullated bed hydroconversion conditions for a liquid hydrocarbon feed. The operating conditions are normally an absolute pressure of 2.5 to 35 MPa, normally 5 to 25 MPa and usually 6 to 20 MPa at a temperature of about 330xc2x0 C. to about 550xc2x0 C. and usually about 350xc2x0 C. to about 500xc2x0 C. The hourly space velocity (HSV) and the hydrogen partial pressure are important factors which are selected as a function of the characteristics of the product to be treated and of the desired conversion. The HSV is usually in a range from about 0.1 hxe2x88x921 to about 10 hxe2x88x921, preferably about 0.2 hxe2x88x921 to about 5 hxe2x88x921. The quantity of hydrogen mixed with the feed is normally about 50 to about 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed and usually about 100 to about 1000 Nm3/m3 and preferably about 200 to about 500 Nm3/m3. A conventional granular hydroconversion catalyst can be used comprising, on an amorphous support, at least one metal or metal compound having an hydrodehydrogenating function. This catalyst can be a catalyst comprising group VIII metals, for example nickel and/or cobalt, usually in combination with at least one group VIB metal, for example molybdenum and/or tungsten. As an example, it is possible to use a catalyst comprising 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as nickel oxide NiO) and 1% to 30% by weight of molybdenum, preferably 5% to 20% by weight of molybdenum (expressed as molybdenum oxide (MoO3) on an amorphous mineral support. This support is, for example, selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support can also comprise other compounds, for example oxides selected from the group formed by boron oxide, zirconia, titanium oxide, or phosphorous pentoxide. Usually, an alumina support is used, and more usually an alumina support doped with phosphorous and optionally boron. The concentration of phosphorous pentoxide P2O5 is normally less than about 20% by weight and usually less than about 10% by weight. This concentration of P2O5 is normally at least 0.001% by weight. The concentration of boron trioxide B2O3 is normally about 0 to about 10% by weight. The alumina used is normally a xcex3 or xcex7 alumina. This catalyst is usually in the form of extrudates.
The total content of oxides of metals from groups VI and VIII is usually about 5% to about 40% by weight, and in general about 7% to 30% by weight and the weight ratio, expressed as the metallic oxide, of the group VI metal (or metals) over the group VIII metal (or metals) is in general about 20 to about 1, usually about 10 to about 2. Part of the used catalyst is replaced with fresh catalyst by withdrawal from the bottom of the reactor and introducing fresh or new catalyst to the top of the reactor at regular intervals, i.e., batchwise or quasi-continuously. As an example, fresh catalyst can be introduced every day. The ratio for replacing used catalyst with fresh catalyst can, for example, be about 0.05 kilograms to about 10 kilograms per cubic meter of feed. This withdrawal and replacement are carried out using apparatus enabling continuous operation of this hydroconversion step. The unit normally comprises a recirculating pump enabling the catalyst to be kept under ebullated bed conditions by continuously recycling at least a portion of the liquid withdrawn from the top of the reactor and reinjected into the reactor bottom. It is also possible to send the used catalyst withdrawn from the reactor to a regeneration zone in which the carbon and sulphur which it comprises are eliminated, then returning the regenerated catalyst to hydroconversion step a).
This hydroconversion step a) is usually carried out under the conditions of the H-OIL(copyright) process as described, for example, in the article published by the NPRA Annual Meeting, March 16-18, 1997, J. J. Colyar and L. I. Wilson, entitled xe2x80x9cThe H-Oil process, a worldwide leader in vacuum residue hydroprocessingxe2x80x9d.
In the variation mentioned above (step a1)), the products obtained during this step a) are, sent to a separation zone from which a heavy liquid fraction and a lighter fraction are recovered. Normally, the initial boiling point of this heavy liquid fraction is about 280xc2x0 C. to about 570xc2x0 C., preferably about 350xc2x0 C. to about 520xc2x0 C., for example about 400xc2x0 C. The lighter fraction is normally used in a separation zone in which it is split into light gasoline and gas oil fractions at least a part of which can be sent to fuel storage zones, and into a heavier fraction.
In hydrotreatment step c), a conventional hydrotreatment catalyst is usually used, preferably at least one of those described by the Applicant, in particular one of those described in patents EP-B-0 113 297 and EP-B-0 113 284. generally, an absolute pressure of about 2 to 35 MPa is used, normally about 5 to 25 MPa and usually about 6 to 20 MPa. The temperature in this step b) is generally about 300xc2x0 C. to about 500xc2x0 C., normally about 350xc2x0 C. to about 450xc2x0 C. and usually about 350xc2x0 C. to about 420xc2x0 C. This temperature is normally adjusted depending on the desired level of hydrodesulphurisation. The hourly space velocity (HSV) and the hydrogen partial pressure are important factors which are selected as a function of the characteristics of the product to be treated and of the desired conversion. The HSV is usually in a range from about 0.1 hxe2x88x921 to about 5 hxe2x88x921, preferably about 0.2 h xe2x88x921 to about 2 hxe2x88x921. The quantity of hydrogen mixed with the feed is normally about 100 to about 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed, usually about 200 to about 2000 Nm3/m3 and preferably about 300 to about 1500 Nm3/m3. It is normally carried out in the presence of hydrogen sulphide and the partial pressure of hydrogen sulphide is by about 0.002 times to about 0.1 times, preferably about 0.005 times to about 0.05 times the total pressure. In the hydrodesulphurisation zone, the ideal catalyst must have a strong hydrogenating power in order to carry out deep refining of the products and to obtain a substantial reduction in sulphur content. In the preferred implementation, the hydrotreatment zone is operated at a relatively low temperature which tends in the direction of deep hydrogenation and limitation of coking. The scope of the present invention encompasses using a single catalyst or a plurality of different catalysts in the hydrotreatment zone, simultaneously or successively. Normally this step c) is carried out on an industrial scale in one or more reactors in liquid downflow mode.
In the hydrotreatment zone (step c)), at least one fixed bed of conventional hydrotreatment catalyst is used, the support of which is at least partially amorphous. Preferably, a catalyst is used with a support which is, for example, selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support can also comprise other compounds, for example oxides selected from the group formed by boron oxide, zirconia, titanium oxide and phosphorous pentoxide. Usually, an alumina support is used, more specifically an alumina support doped with phosphorous and possibly boron. The concentration of phosphorous pentoxide P2O5 is normally less than about 20% by weight and usually less than about 10% by weight. This concentration of P2O5 is normally at least 0.001% by weight. The concentration of boron trioxide B2O3 is normally about 0 to about 10% by weight. The alumina used is normally a xcex3 or a xcex7 alumina. This catalyst is usually in the form of beads or extrudates. A conventional granular hydrotreatment catalyst comprising at least one metal or metal compound with a hydrodehydrogenating function on an amorphous support can be used. This catalyst can be a catalyst comprising group VIII metals, for example nickel and/or cobalt, usually in combination with at least one group VIb metal, for example molybdenum and/or tungsten. As an example, it is possible to use a catalyst comprising 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as nickel oxide NiO) and 1% to 30% by weight of molybdenum, preferably 5% to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3) on an amorphous mineral support. The total amount of group VI and VIII metal oxides is usually about 5% to about 40% by weight, generally about 7% to 30% by weight and the weight ratio, expressed as the metal oxide, between the group VI metal (or metals) and the group VIII metal (or metals) is generally about 20 to about 1, usually about 10 to about 2.
In the distillation zone of step d), the conditions are generally selected such that the cut point for the heavy feed is about 350xc2x0 C. to about 400xc2x0 C., preferably about 360xc2x0 C. to about 380xc2x0 C., for example about 370xc2x0 C. In this distillation zone, a gasoline fraction is also recovered with an end point which is usually about 150xc2x0 C., and a gas oil fraction with an initial boiling point which is normally about 150xc2x0 C. and an end point which is about 370xc2x0 C.
Finally, in a variation mentioned above, in catalytic cracking step e) at least a portion of the heavy fraction of the hydrotreated feed obtained in step d) can be sent to a catalytic cracking section in which it is catalytically cracked in a conventional manner under conditions which are well known to the skilled person, to produce a fuel fraction (comprising a gasoline fraction and a gas oil fraction) at least a portion of which is normally sent to fuel storage zones and into a slurry fraction at least a portion or all of which, for example, is sent to the heavy fuel pool or at a portion or all of which is recycled to catalytic cracking step e). In the present invention, the expression xe2x80x9ccatalytic crackingxe2x80x9d encompasses all cracking processes which treat a heavy fraction with a high Conradson Carbon, for example those using temperature control techniques such as MTC techniques, or the catalyst temperature control technique such as those known in the art as a catalyst cooler. In a particular implementation of the invention, a portion of the gas oil fraction (either LCO, or HCO, or DO, or slurry) obtained during step e) is recycled either to step a), or to step c), or to step e) mixed with the feed introduced into this catalytic cracking step e). In the present description, the term xe2x80x9ca portion of the gas oil fractionxe2x80x9d is understood to means a fraction less than 100%. The scope of the present invention also encompasses recycling a portion of the gas oil fraction (LCO, HCO, slurry, DO) to step a), a portion to step c) and a further portion to step e), the ensemble of these portions clearly not representing the whole of the gas oil fraction. It is also possible, in the present invention, to recycle all of the gas oil fraction (LCO, HCO, DO, slurry) obtained by catalytic cracking either to step a), or to step c), or to step e), or a fraction to each of these steps, the sum of these fractions representing up to 100% of the gas oil fraction obtained in step e). It is also possible to recycle at least a portion of the gasoline fraction obtained in this catalytic cracking step e) to step e).
Catalytic cracking step e) is usually a fluidised bed catalytic cracking step, for example using the R2R process developed by the Applicant. This step can be carried out conventionally in a known manner under suitable cracking conditions to produce lower molecular weight hydrocarbon products. This step can use heat exchange apparatus and processes, in particular for solid particles, to reduce the temperature of the catalyst at the inlet to the reaction zone. Descriptions of the operation and catalysts suitable for fluidised bed cracking in step e) have been described, for example, in patents U.S. Pat. No. 4,695,370, EP-B-0-184 517, U.S. Pat. No. 4,959,334, EP-B-0 323 297, U.S. Pat. Nos. 4,965,232, 5,120,691, 5,344,554, 5,449,496, EP-A-0 485 259, U.S. Pat. Nos. 5,286,690, 5,324,696, EP-B-0 542 604 and EP-A-0 699 224, the descriptions of which are hereby deemed to be incorporated in the present description by reference.
The fluidised bed catalytic cracking reactor can operate in upflow or downflow mode. While this is not a preferred embodiment of the present invention, it is also possible to carry out the catalytic cracking in a moving bed reactor. Particularly preferred catalytic cracking catalysts are those which contain at least one zeolite which is normally mixed with a suitable matrix such as alumina, silica or silica-alumina.